In situ fluid dynamics and CO2 injection in porous rocks

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Abstract

Understanding multiphase fluid flow in porous rocks implies knowledge of fundamental
properties such as wettability, relative permeability and capillary pressure. These
parameters, as well as the extent of fractures and their permeability and
interconnection, are vital information needed to predict oil recovery, select production
scenario and initiate EOR strategies in the reservoir. In this thesis, wettability, relative
permeability and capillary pressure are measured directly from in situ saturation and
pressure data and the impacts on oil recovery from capillary continuity across fractures
have been studied. Finally, injection of CO2 to enhance oil recovery is investigated at
different wettabilities and when varying a wide range of injection scenarios.
Conventionally, relative permeability curves are generated from capillary pressure
curves using best-fit analyses of the production data. Experimental methods to measure
relative permeability include unsteady-state methods which are based on production
data and average pressure drop across entire core samples. They may thus fail to
capture capillary end effects and local variations and heterogeneities. The steady-state
methods claim to describe dynamic properties but rely on pressure or saturation
equilibrium. Alternatively, some steady-state methods are based on simultaneous
injection of one wetting and one non-wetting fluid phase but aim to describe the
properties of either drainage or imbibition processes.
An alternative, explicit method to calculate relative permeabilities has been reviewed
and slightly modified in this thesis, and dynamic capillary pressure curves have been
measured at different wettabilities based on in situ saturation and phase pressure data
collected during continuous flooding. Both methods utilize dynamic measurements to
describe the properties of relative permeability and capillary pressure as opposed to
most conventional methods. The relative permeability curves showed consistency with
wettability, and a good match with conventional curves at strongly water-wet conditions
was obtained. The capillary pressure curves corroborated data obtained from centrifuge
experiments at strongly water-wet, less water-wet and near neutral-wet conditions. In
addition, the proposed methods for obtaining both relative permeability and capillary
pressure curves are time-saving, and in situ data increased the accuracy and confidence
of the input to numerical simulators used to predict reservoir fluid flow.
A drawback with the conventional Amott-Harvey Index of wettability measurement
method is the time consumed from obtaining spontaneous imbibition data. The
possibility to capture local heterogeneities is also limited in this method, as the data
collected from imbibition and subsequent water- or oilfloods are average measures
obtained from whole core samples. In this work, local wettability indices are measured
during continuous flooding from in situ saturation and local pressure data by identifying
the separate contributions to oil recovery from spontaneous imbibition and viscous
displacement. The obtained wettability indices demonstrate an excellent match with the
conventional data.
Previous work has shown that wetting phase bridges across an open fracture establish
capillary continuity between two mixed-wet matrix blocks and increase oil recovery
exceeding the end-point for spontaneous imbibition. However, the wetting phase
produced from the inlet matrix block during drainage of strongly wetted systems forms a film on the outlet end and fails to establish capillary continuity across the fracture. In
this work, capillary continuity in strongly wetted systems has been established during
drainage processes by packing the separating fracture with micro-particles. Capillary
continuity was determined by monitoring the volume accumulated by the capillary end
effect during continuous injection of the non-wetting phase.
The demand for enhanced oil recovery in mature oil fields combined with carbon
neutral solutions and high quality in situ data is increasing. Several projects have been
initiated worldwide to capture CO2 from fossil fuel-fired power plants and other
industrial processes, and CO2 is thus becoming more available for EOR projects. In order
to further increase the understanding of multiphase dynamic fluid flow in porous media,
MRI was used to monitor in situ saturation development during injection of liquid or
supercritical CO2 at different wettabilities and at miscible conditions. A series of
experiments was initiated to study oil recovery potential from injection of compressed
CO2 at secondary and tertiary conditions, monitor in situ fluid flow and investigate oil
recovery mechanisms in low-permeable outcrop chalk. Qualitative analysis of the MRI
images indicated oil swelling at the front as the CO2 propagated through the cores, and
enhanced oil recovery ranging from 9.4 %PV to 67 %PV was determined from material
balance calculations. During tertiary injection of liquid CO2 in a fractured core sample,
MRI images suggested that the oil in the middle and outlet end of the core was bypassed
due to high fracture permeability.
The results obtained from the various experiments emphasize the importance of using
high spatial resolution saturation imaging, providing increased understanding of
multiphase in situ fluid flow in porous media, assisting in predicting recovery
mechanisms and improving input data used in numerical simulators.

Has part(s)

Paper 1: Brautaset, A.; Ersland, G.; Graue, A., 2009, In situ Phase Pressures and Fluid Saturation Dynamics Measured in Waterfloods at Various Wettability conditions. Full text not available in BORA.